Integrated skidding rig system

ABSTRACT

A rig system and a method for drilling a well. The rig system includes a movable central package including one or more devices to drill a well using a drill pipe, a mud pump coupled with the movable central package and configured to pump mud thereto, and a cement pump coupled with the movable central package. The cement pump is operable in a first mode in which the cement pump pumps cement to the well, and a second mode in which the cement pump pumps mud to the well.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Patent Application having Ser.No. 62/238,508, which was filed on Oct. 7, 2015 and is incorporated byreference herein in its entirety.

BACKGROUND

A drilling rig may be used to drill wellbores into the Earth in order torecover fluid, such as hydrocarbons, therefrom. Generally, drilling rigsare relatively large structures, which include a rig floor with a rotarytable or bushing therein that provides access through the rig floor tothe top of the well (“well head”). The rig may also include a drillingassembly, which may include a top drive suspended from a travellingblock and supported by a mast. An elevator, pipe manipulator, or anothertype of hoisting structure may be attached to a stand of tubulars (e.g.,one or more joints of drill pipe), lifting the stand into position abovethe well. Each successive stand is threaded (“made-up”) to thepreviously-run joint, and then the string is lowered generally by thelength of the new stand. This process is repeated for potentiallyhundreds of stands of pipe, until the well reaches a desired depth.During the drilling process, the well is typically cased and cementedafter sections of the well are drilled. During such casing andcementing, the drilling process stops and restarts after the cement hassufficiently set in the well.

Multiple wells may be drilled over one pad. This is a convenient methodto limit the number of times that well equipment may be accessed duringdrilling and production. In such application, the drilling rig maycomplete one well, then it may be skidded (moved) to the next welllocation with minimum disassembly, and then the next well of the pad canbe drilled and completed.

Recently, a batch drilling concept has been identified as a way toreduce delays due to the staged drilling, casing, and cementingoperations. Basically, several wells in an identified location (“pad”)are drilled in parallel using a single, movable rig. Thus, for example,a top section of a first well may be drilled, and then the rig may moveto a second location on the pad, and drill a top section of a secondwell. Meanwhile, the top section of the first well is cased andcemented. After a certain number of top sections of different wells aredrilled, the rig returns to the first well and drills the next section,and the process repeats.

Movable (“skiddable”) rigs, however, present a host of challenges, sincemost rig technology is designed for generally stationary rigs meant tocomplete one well at a time. Moreover, the complexity introduced by themovable rigs may call for additional personnel and/or more-qualifiedpersonnel at the rig site, and additional hydraulic and electricalconnections between the stationary components and the movablecomponents, which may at least partially negate cost savings realized bygreater efficiency using batch drilling techniques.

Furthermore, in many drilling operations, different service companiesprovide various different components of the drilling rig system. Forexample, one company might provide the managed pressure drilling system,while another might provide cement pumps, and a third provides mudpumps. Each time a service is completed, the associated service providermay remove its equipment and move to another job or location.

SUMMARY

Embodiments of the disclosure may provide a rig system. The rig systemincludes a movable central package including one or more devices todrill a well using a drill pipe, a mud pump coupled with the movablecentral package and configured to pump mud thereto, and a cement pumpcoupled with the movable central package. The cement pump is operable ina first mode in which the cement pump pumps cement to the well, and asecond mode in which the cement pump pumps mud to the well.

Embodiments of the disclosure may further provide a method for drillinga well using a movable rig. The method includes pumping a mud into awellbore using at least one mud pump while drilling the wellbore,pumping the mud into the wellbore using at least one cement pump in afirst mode, while drilling the wellbore and while pumping mud into thewellbore using the at least one mud pump, and pumping cement into thewellbore using the at least one cement pump in a second mode.

Embodiments of the disclosure may also provide a rig system. The rigsystem includes a movable central package comprising one or more devicesto drill a well using a drill pipe, and a mud pump coupled with themovable central package and configured to pump mud thereto. The mud pumpis configured to pump the mud in a first mode, and wherein the mud pumpis configured to pump cement to the central package in a second mode.The system further includes a cement pump coupled with the movablecentral package, with the cement pump being operable in a first mode inwhich the cement pump pumps cement to the well, and a second mode inwhich the cement pump pumps mud to the well. The system also includes acombined skid that is movable along with the movable central package,with the combined skid including a managed pressure drilling system anda shaker assembly. The system additionally includes a plurality ofvariable frequency drives (VFDs), with individual VFDs being separatelycoupled to the central package, the mud pump, and the cement pump. Thesystem further includes a plurality of controllers, with individualcontrollers of the plurality of controllers being separately coupled tothe central package, the mud pump, and the cement pump, to providequasi-independent control thereof. Further, the movable central packageis movable relative to the mud pump and the cement pump, and wherein themovable central package is configured for batch drilling.

It will be appreciated that the foregoing summary is intended merely tointroduce a subset of the features described in greater detail below,and is not intended to be exhaustive or to limit the scope of thedisclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute apart of this specification, illustrate embodiments of the presentteachings and together with the description, serve to explain theprinciples of the present teachings. In the figures:

FIG. 1 illustrates a schematic view of a drilling rig and a controlsystem, according to an embodiment.

FIG. 2 illustrates a schematic view of a drilling rig and a remotecomputing resource environment, according to an embodiment.

FIG. 3 illustrates a plan, schematic view of a drilling rig system,according to an embodiment.

FIG. 4 illustrates a conceptual, schematic view of a portion of thedrilling rig system, according to an embodiment.

FIG. 5 illustrates a conceptual, schematic view of electricalconnections between a generator and several example subsystems of thedrilling rig, according to an embodiment.

FIG. 6 illustrates a schematic view of a computing system, according toan embodiment.

DETAILED DESCRIPTION

Reference will now be made in detail to specific embodiments illustratedin the accompanying drawings and figures. In the following detaileddescription, numerous specific details are set forth in order to providea thorough understanding of the invention. However, it will be apparentto one of ordinary skill in the art that embodiments may be practicedwithout these specific details. In other instances, well-known methods,procedures, components, circuits, and networks have not been describedin detail so as not to unnecessarily obscure aspects of the embodiments.

It will also be understood that, although the terms first, second, etc.may be used herein to describe various elements, these elements shouldnot be limited by these terms. These terms are only used to distinguishone element from another. For example, a first object could be termed asecond object or step, and, similarly, a second object could be termed afirst object or step, without departing from the scope of the presentdisclosure.

The terminology used in the description of the invention herein is forthe purpose of describing particular embodiments only and is notintended to be limiting. As used in the description of the invention andthe appended claims, the singular forms “a,” “an” and “the” are intendedto include the plural forms as well, unless the context clearlyindicates otherwise. It will also be understood that the term “and/or”as used herein refers to and encompasses any and all possiblecombinations of one or more of the associated listed items. It will befurther understood that the terms “includes,” “including,” “comprises”and/or “comprising,” when used in this specification, specify thepresence of stated features, integers, steps, operations, elements,and/or components, but do not preclude the presence or addition of oneor more other features, integers, steps, operations, elements,components, and/or groups thereof. Further, as used herein, the term“if” may be construed to mean “when” or “upon” or “in response todetermining” or “in response to detecting,” depending on the context.

FIG. 1 illustrates a conceptual, schematic view of a control system 100for a drilling rig 102, according to an embodiment. The control system100 may include a rig computing resource environment 105, which may belocated onsite at the drilling rig 102 and, in some embodiments, mayhave a coordinated control device 104. The control system 100 may alsoprovide a supervisory control system 107. In some embodiments, thecontrol system 100 may include a remote computing resource environment106, which may be located offsite from the drilling rig 102.

The remote computing resource environment 106 may include computingresources locating offsite from the drilling rig 102 and accessible overa network. A “cloud” computing environment is one example of a remotecomputing resource. The cloud computing environment may communicate withthe rig computing resource environment 105 via a network connection(e.g., a WAN or LAN connection). In some embodiments, the remotecomputing resource environment 106 may be at least partially locatedonsite, e.g., allowing control of various aspects of the drilling rig102 onsite through the remote computing resource environment 105 (e.g.,via mobile devices). Accordingly, “remote” should not be limited to anyparticular distance away from the drilling rig 102.

Further, the drilling rig 102 may include various systems with differentsensors and equipment for performing operations of the drilling rig 102,and may be monitored and controlled via the control system 100, e.g.,the rig computing resource environment 105. Additionally, the rigcomputing resource environment 105 may provide for secured access to rigdata to facilitate onsite and offsite user devices monitoring the rig,sending control processes to the rig, and the like.

Various example systems of the drilling rig 102 are depicted in FIG. 1.For example, the drilling rig 102 may include a downhole system 110, afluid system 112, and a central system 114. These systems 110, 112, 114may also be examples of “subsystems” of the drilling rig 102, asdescribed herein. In some embodiments, the drilling rig 102 may includean information technology (IT) system 116. The downhole system 110 mayinclude, for example, a bottomhole assembly (BHA), mud motors, sensors,etc. disposed along the drill string, and/or other drilling equipmentconfigured to be deployed into the wellbore. Accordingly, the downholesystem 110 may refer to tools disposed in the wellbore, e.g., as part ofthe drill string used to drill the well.

The fluid system 112 may include, for example, drilling mud, pumps,valves, cement, mud-loading equipment, mud-management equipment,pressure-management equipment, separators, and other fluids equipment.Accordingly, the fluid system 112 may perform fluid operations of thedrilling rig 102.

The central system 114 may include a hoisting and rotating platform, topdrives, rotary tables, kellys, drawworks, pumps, generators, tubularhandling equipment, derricks, masts, substructures, and other suitableequipment. Accordingly, the central system 114 may perform powergeneration, hoisting, and rotating operations of the drilling rig 102,and serve as a support platform for drilling equipment and stagingground for rig operation, such as connection make up, etc. The IT system116 may include software, computers, and other IT equipment forimplementing IT operations of the drilling rig 102.

The control system 100, e.g., via the coordinated control device 104 ofthe rig computing resource environment 105, may monitor sensors frommultiple systems of the drilling rig 102 and provide control commands tomultiple systems of the drilling rig 102, such that sensor data frommultiple systems may be used to provide control commands to thedifferent systems of the drilling rig 102. For example, the system 100may collect temporally and depth aligned surface data and downhole datafrom the drilling rig 102 and store the collected data for access onsiteat the drilling rig 102 or offsite via the rig computing resourceenvironment 105. Thus, the system 100 may provide monitoring capability.Additionally, the control system 100 may include supervisory control viathe supervisory control system 107.

In some embodiments, one or more of the downhole system 110, fluidsystem 112, and/or central system 114 may be manufactured and/oroperated by different vendors. In such an embodiment, certain systemsmay not be capable of unified control (e.g., due to different protocols,restrictions on control permissions, safety concerns for differentcontrol systems, etc.). An embodiment of the control system 100 that isunified, may, however, provide control over the drilling rig 102 and itsrelated systems (e.g., the downhole system 110, fluid system 112, and/orcentral system 114, etc.). Further, the downhole system 110 may includeone or a plurality of downhole systems. Likewise, fluid system 112, andcentral system 114 may contain one or a plurality of fluid systems andcentral systems, respectively.

In addition, the coordinated control device 104 may interact with theuser device(s) (e.g., human-machine interface(s)) 118, 120. For example,the coordinated control device 104 may receive commands from the userdevices 118, 120 and may execute the commands using two or more of therig systems 110, 112, 114, e.g., such that the operation of the two ormore rig systems 110, 112, 114 act in concert and/or off-designconditions in the rig systems 110, 112, 114 may be avoided.

FIG. 2 illustrates a conceptual, schematic view of the control system100, according to an embodiment. The rig computing resource environment105 may communicate with offsite devices and systems using a network 108(e.g., a wide area network (WAN) such as the internet). Further, the rigcomputing resource environment 105 may communicate with the remotecomputing resource environment 106 via the network 108. FIG. 2 alsodepicts the aforementioned example systems of the drilling rig 102, suchas the downhole system 110, the fluid system 112, the central system114, and the IT system 116. In some embodiments, one or more onsite userdevices 118 may also be included on the drilling rig 102. The onsiteuser devices 118 may interact with the IT system 116. The onsite userdevices 118 may include any number of user devices, for example,stationary user devices intended to be stationed at the drilling rig 102and/or portable user devices. In some embodiments, the onsite userdevices 118 may include a desktop, a laptop, a smartphone, a personaldata assistant (PDA), a tablet component, a wearable computer, or othersuitable devices. In some embodiments, the onsite user devices 118 maycommunicate with the rig computing resource environment 105 of thedrilling rig 102, the remote computing resource environment 106, orboth.

One or more offsite user devices 120 may also be included in the system100. The offsite user devices 120 may include a desktop, a laptop, asmartphone, a personal data assistant (PDA), a tablet component, awearable computer, or other suitable devices. The offsite user devices120 may be configured to receive and/or transmit information (e.g.,monitoring functionality) from and/or to the drilling rig 102 viacommunication with the rig computing resource environment 105. In someembodiments, the offsite user devices 120 may provide control processesfor controlling operation of the various systems of the drilling rig102. In some embodiments, the offsite user devices 120 may communicatewith the remote computing resource environment 106 via the network 108.

The user devices 118 and/or 120 may be examples of a human-machineinterface. These devices 118, 120 may allow feedback from the variousrig subsystems to be displayed and allow commands to be entered by theuser. In various embodiments, such human-machine interfaces may beonsite or offsite, or both.

The systems of the drilling rig 102 may include various sensors,actuators, and controllers (e.g., programmable logic controllers(PLCs)), which may provide feedback for use in the rig computingresource environment 105. For example, the downhole system 110 mayinclude sensors 122, actuators 124, and controllers 126. The fluidsystem 112 may include sensors 128, actuators 130, and controllers 132.Additionally, the central system 114 may include sensors 134, actuators136, and controllers 138. The sensors 122, 128, and 134 may include anysuitable sensors for operation of the drilling rig 102. In someembodiments, the sensors 122, 128, and 134 may include a camera, apressure sensor, a temperature sensor, a flow rate sensor, a vibrationsensor, a current sensor, a voltage sensor, a resistance sensor, agesture detection sensor or device, a voice actuated or recognitiondevice or sensor, or other suitable sensors.

The sensors described above may provide sensor data feedback to the rigcomputing resource environment 105 (e.g., to the coordinated controldevice 104). For example, downhole system sensors 122 may provide sensordata 140, the fluid system sensors 128 may provide sensor data 142, andthe central system sensors 134 may provide sensor data 144. The sensordata 140, 142, and 144 may include, for example, equipment operationstatus (e.g., on or off, up or down, set or release, etc.), drillingparameters (e.g., depth, hook load, torque, etc.), auxiliary parameters(e.g., vibration data of a pump) and other suitable data. In someembodiments, the acquired sensor data may include or be associated witha timestamp (e.g., a date, time or both) indicating when the sensor datawas acquired. Further, the sensor data may be aligned with a depth orother drilling parameter.

Acquiring the sensor data into the coordinated control device 104 mayfacilitate measurement of the same physical properties at differentlocations of the drilling rig 102. In some embodiments, measurement ofthe same physical properties may be used for measurement redundancy toenable continued operation of the well. In yet another embodiment,measurements of the same physical properties at different locations maybe used for detecting equipment conditions among different physicallocations. In yet another embodiment, measurements of the same physicalproperties using different sensors may provide information about therelative quality of each measurement, resulting in a “higher” qualitymeasurement being used for rig control, and process applications. Thevariation in measurements at different locations over time may be usedto determine equipment performance, system performance, scheduledmaintenance due dates, and the like. Furthermore, aggregating sensordata from each subsystem into a centralized environment may enhancedrilling process and efficiency. For example, slip status (e.g., in orout) may be acquired from the sensors and provided to the rig computingresource environment 105, which may be used to define a rig state forautomated control. In another example, acquisition of fluid samples maybe measured by a sensor and related with bit depth and time measured byother sensors. Acquisition of data from a camera sensor may facilitatedetection of arrival and/or installation of materials or equipment inthe drilling rig 102. The time of arrival and/or installation ofmaterials or equipment may be used to evaluate degradation of amaterial, scheduled maintenance of equipment, and other evaluations.

The coordinated control device 104 may facilitate control of individualsystems (e.g., the central system 114, the downhole system, or fluidsystem 112, etc.) at the level of each individual system. For example,in the fluid system 112, sensor data 128 may be fed into the controller132, which may respond to control the actuators 130. However, forcontrol operations that involve multiple systems, the control may becoordinated through the coordinated control device 104. Examples of suchcoordinated control operations include the control of downhole pressureduring tripping. The downhole pressure may be affected by both the fluidsystem 112 (e.g., pump rate and choke position) and the central system114 (e.g. tripping speed). When it is desired to maintain certaindownhole pressure during tripping, the coordinated control device 104may be used to direct the appropriate control commands. Furthermore, formode based controllers which employ complex computation to reach acontrol setpoint, which are typically not implemented in the subsystemPLC controllers due to complexity and high computing power demands, thecoordinated control device 104 may provide the adequate computingenvironment for implementing these controllers.

In some embodiments, control of the various systems of the drilling rig102 may be provided via a multi-tier (e.g., three-tier) control systemthat includes a first tier of the controllers 126, 132, and 138, asecond tier of the coordinated control device 104, and a third tier ofthe supervisory control system 107. The first tier of the controllersmay be responsible for safety critical control operation, or fast loopfeedback control. The second tier of the controllers may be responsiblefor coordinated controls of multiple equipment or subsystems, and/orresponsible for complex model based controllers. The third tier of thecontrollers may be responsible for high level task planning, such as tocommand the rig system to maintain certain bottom hole pressure. Inother embodiments, coordinated control may be provided by one or morecontrollers of one or more of the drilling rig systems 110, 112, and 114without the use of a coordinated control device 104. In suchembodiments, the rig computing resource environment 105 may providecontrol processes directly to these controllers for coordinated control.For example, in some embodiments, the controllers 126 and thecontrollers 132 may be used for coordinated control of multiple systemsof the drilling rig 102.

The sensor data 140, 142, and 144 may be received by the coordinatedcontrol device 104 and used for control of the drilling rig 102 and thedrilling rig systems 110, 112, and 114. In some embodiments, the sensordata 140, 142, and 144 may be encrypted to produce encrypted sensor data146. For example, in some embodiments, the rig computing resourceenvironment 105 may encrypt sensor data from different types of sensorsand systems to produce a set of encrypted sensor data 146. Thus, theencrypted sensor data 146 may not be viewable by unauthorized userdevices (either offsite or onsite user device) if such devices gainaccess to one or more networks of the drilling rig 102. The sensor data140, 142, 144 may include a timestamp and an aligned drilling parameter(e.g., depth) as discussed above. The encrypted sensor data 146 may besent to the remote computing resource environment 106 via the network108 and stored as encrypted sensor data 148.

The rig computing resource environment 105 may provide the encryptedsensor data 148 available for viewing and processing offsite, such asvia offsite user devices 120. Access to the encrypted sensor data 148may be restricted via access control implemented in the rig computingresource environment 105. In some embodiments, the encrypted sensor data148 may be provided in real-time to offsite user devices 120 such thatoffsite personnel may view real-time status of the drilling rig 102 andprovide feedback based on the real-time sensor data. For example,different portions of the encrypted sensor data 146 may be sent tooffsite user devices 120. In some embodiments, encrypted sensor data maybe decrypted by the rig computing resource environment 105 beforetransmission or decrypted on an offsite user device after encryptedsensor data is received.

The offsite user device 120 may include a client (e.g., a thin client)configured to display data received from the rig computing resourceenvironment 105 and/or the remote computing resource environment 106.For example, multiple types of thin clients (e.g., devices with displaycapability and minimal processing capability) may be used for certainfunctions or for viewing various sensor data.

The rig computing resource environment 105 may include various computingresources used for monitoring and controlling operations such as one ormore computers having a processor and a memory. For example, thecoordinated control device 104 may include a computer having a processorand memory for processing sensor data, storing sensor data, and issuingcontrol commands responsive to sensor data. As noted above, thecoordinated control device 104 may control various operations of thevarious systems of the drilling rig 102 via analysis of sensor data fromone or more drilling rig systems (e.g. 110, 112, 114) to enablecoordinated control between each system of the drilling rig 102. Thecoordinated control device 104 may execute control commands 150 forcontrol of the various systems of the drilling rig 102 (e.g., drillingrig systems 110, 112, 114). The coordinated control device 104 may sendcontrol data determined by the execution of the control commands 150 toone or more systems of the drilling rig 102. For example, control data152 may be sent to the downhole system 110, control data 154 may be sentto the fluid system 112, and control data 154 may be sent to the centralsystem 114. The control data may include, for example, operator commands(e.g., turn on or off a pump, switch on or off a valve, update aphysical property setpoint, etc.). In some embodiments, the coordinatedcontrol device 104 may include a fast control loop that directly obtainssensor data 140, 142, and 144 and executes, for example, a controlalgorithm. In some embodiments, the coordinated control device 104 mayinclude a slow control loop that obtains data via the rig computingresource environment 105 to generate control commands.

In some embodiments, the coordinated control device 104 may intermediatebetween the supervisory control system 107 and the controllers 126, 132,and 138 of the systems 110, 112, and 114. For example, in suchembodiments, a supervisory control system 107 may be used to controlsystems of the drilling rig 102. The supervisory control system 107 mayinclude, for example, devices for entering control commands to performoperations of systems of the drilling rig 102. In some embodiments, thecoordinated control device 104 may receive commands from the supervisorycontrol system 107, process the commands according to a rule (e.g., analgorithm based upon the laws of physics for drilling operations),and/or control processes received from the rig computing resourceenvironment 105, and provides control data to one or more systems of thedrilling rig 102. In some embodiments, the supervisory control system107 may be provided by and/or controlled by a third party. In suchembodiments, the coordinated control device 104 may coordinate controlbetween discrete supervisory control systems and the systems 110, 112,and 114 while using control commands that may be optimized from thesensor data received from the systems 110 112, and 114 and analyzed viathe rig computing resource environment 105.

The rig computing resource environment 105 may include a monitoringprocess 141 that may use sensor data to determine information about thedrilling rig 102. For example, in some embodiments the monitoringprocess 141 may determine a drilling state, equipment health, systemhealth, a maintenance schedule, or any combination thereof. Furthermore,the monitoring process 141 may monitor sensor data and determine thequality of one or a plurality of sensor data. In some embodiments, therig computing resource environment 105 may include control processes 143that may use the sensor data 146 to optimize drilling operations, suchas, for example, the control of drilling equipment to improve drillingefficiency, equipment reliability, and the like. For example, in someembodiments the acquired sensor data may be used to derive a noisecancellation scheme to improve electromagnetic and mud pulse telemetrysignal processing. The control processes 143 may be implemented via, forexample, a control algorithm, a computer program, firmware, or othersuitable hardware and/or software. In some embodiments, the remotecomputing resource environment 106 may include a control process 145that may be provided to the rig computing resource environment 105.

The rig computing resource environment 105 may include various computingresources, such as, for example, a single computer or multiplecomputers. In some embodiments, the rig computing resource environment105 may include a virtual computer system and a virtual database orother virtual structure for collected data. The virtual computer systemand virtual database may include one or more resource interfaces (e.g.,web interfaces) that enable the submission of application programminginterface (API) calls to the various resources through a request. Inaddition, each of the resources may include one or more resourceinterfaces that enable the resources to access each other (e.g., toenable a virtual computer system of the computing resource environmentto store data in or retrieve data from the database or other structurefor collected data).

The virtual computer system may include a collection of computingresources configured to instantiate virtual machine instances. Thevirtual computing system and/or computers may provide a human-machineinterface through which a user may interface with the virtual computersystem via the offsite user device or, in some embodiments, the onsiteuser device. In some embodiments, other computer systems or computersystem services may be utilized in the rig computing resourceenvironment 105, such as a computer system or computer system servicethat provisions computing resources on dedicated or sharedcomputers/servers and/or other physical devices. In some embodiments,the rig computing resource environment 105 may include a single server(in a discrete hardware component or as a virtual server) or multipleservers (e.g., web servers, application servers, or other servers). Theservers may be, for example, computers arranged in any physical and/orvirtual configuration

In some embodiments, the rig computing resource environment 105 mayinclude a database that may be a collection of computing resources thatrun one or more data collections. Such data collections may be operatedand managed by utilizing API calls. The data collections, such as sensordata, may be made available to other resources in the rig computingresource environment or to user devices (e.g., onsite user device 118and/or offsite user device 120) accessing the rig computing resourceenvironment 105. In some embodiments, the remote computing resourceenvironment 106 may include similar computing resources to thosedescribed above, such as a single computer or multiple computers (indiscrete hardware components or virtual computer systems).

FIG. 3 illustrates a schematic plan view of a drilling rig system 300,according to an embodiment. The system 300 may include a central package302 that may perform the actual drilling operations. For example, thecentral package 302 may include a rig floor 304, from which a mast 306may extend upward. The mast 306 may support rotating drilling equipment,such as a top drive, kelly, or the like, which may be operable to rotatedrill pipe in at least some situations. Such rotation may be convertedinto drilling operations through the use of a bottomhole assembly,including a drill bit, which is run into the wellbore along with thedrill string.

The central package 302 may also include a catwalk 308 and a pipe rack310, which may be configured to hold pipe joints and/or stands of two orthree pipe joints, for example, horizontally. The catwalk 308 may movewith the central package 302. The pipe rack 310 may be configured tofacilitate moving each stand onto the catwalk 308. Once at the catwalk308, hoisting equipment may be employed to raise the stand to a verticalorientation above the well. The stand may then be made up to themost-recently run stand, e.g., using tongs or the top drive. A drawworkssystem may then lower the stand, along with the rest of the string,e.g., as the top drive rotates the string thereby advancing the bit intothe well.

The central package 302 may further include an electrical power control312. The control 312 may include a variable frequency drive (VFD) whichmay facilitate modulation of power, speed, etc., to the various motorson the central package 302 (e.g., the top drive motor, drawworks motor,etc.). Further, the central package 302 may be configured to be mobileso as to move from well to well in a predefined region or “pad” andconduct batch drilling operations. The central package 302 may moveusing wheels, rails, rollers, stompers, or other devices.

The system 300 may further include a combined managed pressure andshaker skid 314 (hereinafter, “combined skid” 314). The combined skid314 may include as one to three, or more, skids depending on the size ofindividual components and/or any other factor. The combined skid 314 mayinclude a well choke manifold, a managed pressure drilling (MPD) chokemanifold, a gas separator, and a trip tank The well choke manifold maybe coupled with the blowout preventer (BOP) of the central package 302,and may be used to close the well, bleed gas from the well, etc. The MPDchoke manifold may be coupled with a rotary control device (RCD) mountedon top of the BOP. Further, the MPD choke manifold may serve to controlfluid pressure in the well. The combined skid 314 may thus be configuredto control the fluid as it exits the well during circulation of mudduring drilling operations. The combined skid 314 may also include ashale shaker, a degasser, a hydrocyclone, and a centrifuge for removingdrill cuttings from the mud as it is returned. The combined skid 314 maybe moved relative to the central package 302. Further, the combined skid314 may move synchronously with the central package 302.

In some embodiments, the mud deployed into and circulated out of thewell may be water based. Accordingly, sedimentary separation of the mudmay additionally or instead be employed, e.g., using a sedimentaryseparation structure 316. The sedimentary separation structure 316 maybe a lined, earthen pit or hole, which may be generallyhorseshoe-shaped. Mud received from the well or otherwise containingsuspended solids (e.g., concrete or cuttings) may be deposited into oneside of the structure 316, and circulated out of another side of thestructure 316, giving the mud sufficient time to allow the suspendedsolids to sink out of suspension. Although the sedimentary separationstructure 316 is illustrated as a single pit, it will be appreciatedthat two pits may be used: one for fresh water and one for brine. Inother embodiments, any other number of pits may be employed.

The system 300 may also include liquid storage 318, e.g., tanks. Forexample, the liquid storage 318 may include one or more tanks for waterand/or oil-based mud. The storage 318 may be provided for when changingbetween different types of drilling fluid.

The system 300 may further include one or more main tanks 320. At leastone of the main tanks 320 may contain mud currently or to be circulatedinto the well, and may contain roughly the same volume as will be usedin the well. At least another one of the main tanks 320 may containwater or premixed cement slurry for use in cementing operations. Drychemicals 322 may be positioned in proximity to the main tanks 320, andthe system 300 may include one or more jet mixers to mix the drychemicals 322 into the main tanks 320. In some embodiments, mud cleaningdevices (such as shale shakers, hydrocyclones and centrifuges) may bemounted in the proximity of the main tanks 320. This may provide foradditional cleaning of the mud.

The system 300 may further include silos 323. The silos 323 may beemployed to store and/or deliver dry additives to well fluids such asmud and cement. For example, four silos may be employed for cement, twofor bentonite and baride, although this is but one specific exampleamong many contemplated.

The system 300 may further include one or more mud pumps 324, which mayeach, or as a group, include a variable frequency drive (VFD) to controlthe speed thereof. These pumps 324 may each be a three-pistonreciprocating pump, and thus may sometimes be referred to as a“triplex”; however, it will be appreciated that any suitable type ofpump may be employed. Further, the system 300 may include a cement unit326 including a cement mixing system and cement pump. The cement pumpmay be a triplex pump. As the names suggest, the mud pumps 324 may beconfigured primarily to pump mud through the well, while the cement pumpof the cement unit 326 may be configured primarily to pump cement intothe well. However, either or both of these functions may be changed,e.g., on demand, as will be described in greater detail below. Thus,unlike other systems in which the cement unit 326 is removed duringmudding operations, and/or the mud pumps 324 are removed duringcementing operations, the present system 300 may combine the resourcesof the two different types of pumps (e.g., cement and mud).

The system 300 may be powered by the generator units 330. For example,several individual generators units 330 may operate in parallel tohandle the power load of the system 300 during drilling and skiddingoperations. Each generator unit 330 may include an alternator driven bya diesel engine, with an electronic controller to ensure speed control(frequency output) as well as phase control between the generator units330. In some embodiments, the generator units 330 may not be moved withthe central package 302. The generator units 330 may be installed in theproximity of the static mud system 320, the pump 324, and/or the cementunit 326.

Furthermore, one or more drive motors may be installed in the system300, e.g., as part of the central package 302. In a specific embodiment,one such motor may operate the drawworks of the central package 302, andanother may be employed to rotate a drill string supported by and runinto the well by the central package 302. Further, the mud pump 324 andthe cement unit 326 may also be provided with power via an electricmotor. Smaller motors may be installed to drive a blower for largemotor(s), one or more centrifugal pumps to move fluids between tanks andto feed the pump 324 and the cement pump, and agitators in the maintanks 320. These electrical motors may be powered via a VFD orsoft-start.

Such components may be installed in a power house (not shown). Thesepower houses may protect the high-power electronics from theenvironment. As the VFD may be positioned a relatively short distanceaway from the motor associated therewith, several power houses may beemployed in the system 300; in particular, one power house may belocated near the pump 324 and the cement unit 326, and one near the rigfloor of the central package 302 to control the motors of the drawworksand top drive.

The system 300 may also include a trunk line 328, which may includeseveral electrical and/or hydraulic lines extending from the generallystationary equipment, such as the mud pumps 324 and tanks 320 to themobile combined skid 314 and/or the mobile central package 302.Furthermore, since the cement unit 326 may kept with the system 300during multiple operations, rather than just during cementing, the trunkline 328 may be employed to connect the cement unit 326 with thecombined skid 314 and/or the central package 302, which may reduce thenumber of separate lines between the mobile central package 302 andcombined skid 314, and the other, relatively stationary components.

In an embodiment, the trunk line 328 may include a mud pump dischargeline, a high-pressure cementing line, a cement return line, and ahydraulic line from the combined skid 314 to the mud tank 320. The mudpump discharge line may be coupled with the mud pumps 324 andselectively coupled with the cement unit 326 and may receive mud atpressure therefrom and route such pressurized mud to the rig floor.Similarly, the cementing line may receive pressurized cement slurry fromthe cement unit 326 and provide the cement to a manifold, which mayconnect with a well kill assembly, the MPD choke manifold, and the well,for delivery of cement thereto. The low-pressure cement return line mayextend from the rig floor to the cement unit 326. The trunk line 328 mayalso include a high-power electrical line, which may route power fromstationary generators 330 to the combined skid 314 and/or the centralpackage 302.

The trunk line 328 may be contained in a “suitcase” assembly of severalarticulating joints which are pivotable with respect to one another.This may facilitate the central package 302 and/or the combined skid 314moving relative to the mud pump 324 and cement unit 326 and tanks 320,etc., while protecting the lines contained within the trunk line 328.The pivots allow the suitcase assembly to be extended or contacted as anaccordion, allowing the change of length between the stationaryequipment and the mobile equipment.

The system 300 may also include pipe storage “tubs” 350, which may storepipe prior to the pipe being loaded into the rack 310. Further, thesystem 300 may include offices or other personnel facilities 352, suchas living quarters.

In some embodiments, the system 300 may also include a fluid-residueskid 360. The fluid-residue skid 360 may move along with the centralpackage 302 and with respect to the tanks 320, mud pump 324, and cementunit 326, etc. The fluid skid may be configured to contain at least someof the fluid received from the well, e.g., from the shale-shaker orcentrifuge of the combined skid 314

FIG. 4 illustrates a schematic of a configuration of the cement unit 326and two mud pumps 324(1), 324(2), according to an embodiment. As notedabove, the cement unit 326 may be or include at least one cement pump,and is thus schematically illustrated as such in FIG. 4, with it beingappreciated that the cement unit 326 may include additional components(e.g., mixers). FIG. 4 also shows a partial view of the trunk line 328,in which a high-pressure mud line 400 and a high-pressure cement line402 are disposed. One of ordinary skill in the art will recognize thatthis figure is intended merely to illustrate the concept of the flowsreaching different locations in an integrated system and thus theparticular arrangement of pumps, valves, etc., as described below, isnot to be considered limiting.

The cement unit 326 and associated main tank 320(2), being an integralpart of the system 300, may allow for the cement unit 326 to perform asa back-up mud pump, for example, when one of the mud pumps 324(1),324(2) is to be shut down for maintenance, etc. Accordingly, the cementunit 326 may be operable in a first mode, in which the cement unit 326pumps cement, as well as in a second mode, in which the cement unit 326pumps mud. During a shutdown of one of the mud pumps 324(1), 324(2)(and/or if additional mud pumping capabilities are otherwise calledfor), the position of a valve 404, 406 upstream of an associated one ofthe mud pumps 324(1), 324(2) may be adjusted, causing mud to be directedto the cement unit 326 instead of the associated mud pump 324(1),324(2). It will be appreciated that a mixing system may be employedin-line, e.g., between the tanks 320(1), 320(2), and the associatedpumps 324(1), 324(2) and the cement unit 326, but is omitted forpurposes of simplicity herein. When mud is routed to the cement unit326, a second valve 408 may be modulated downstream of the cement unit326, directing the fluid pumped by the cement unit 326 to the mud line400 instead of the cement line 402.

Similarly, in some cases, a secondary cement pump may be called for,e.g., in high flow situations, such as during cementing a top section ofa well. Thus, one or both of the mud pumps 324(1), 324(2) may beoperable in a first mode, in which the mud pumps 324(1), 324(2) pumpmud, and a second mode, in which the mud pump(s) 324(1), 324(2) pumpcement. In the second mode, one of the valves 204, 206 may be opened,allowing cement slurry to be introduced to at least one of the mud pumps324(1), 324(2) (e.g., after flushing or otherwise cleaning any remainingmud from the mud pump 324(1) and any active fluid lines). Further, athird valve 210, downstream from either or both of the mud pumps 324(1),324(2) may be modulated to direct fluid to the cement line 202 ratherthan the mud line 200.

In some embodiments, a pulse dampener may be provided on the downstreamside of the mud pumps 324(1) and 324(2). Another type of pulse dampener,which may not be harmed by a flow of cement during cementing operations,or a selectively-active pulse dampener (e.g., isolated from cement flowby a valve), may be positioned downstream of the cement unit 326, andmay be employed for use when the cement unit 326 is pumping mud.

In addition, the tank 320(2) may include two or more sections, e.g.,separated by a baffle, a diaphragm, or any other structure. The sectionsmay be premixed with different amounts of dry additives (e.g., cementcomponents). As such, a lead-in slurry and a tail slurry of differentcompositions may be premixed in the tank 320(2) and pumped into thecement line 202 at the appropriate times during the drilling process.

Referring now to FIGS. 3 and 4, in a situation in which the cement unit326 pumps mud, the cement unit 326 may be controlled along with the mudpumps 324(1), 324(2). Accordingly, a first control panel may be providedat the cement unit 326, and a second control panel may be provided atthe central package 302, with both panels being capable of controllingthe operation of the cement unit 326, e.g., by setting the speed usingthe VFD of the cement unit 326. Accordingly, during drilling operations,when the cement unit 326 is switched to pumping mud (i.e., switched tothe second mode), the second panel may control operation of the cementunit 326. During cementing operations (i.e., when the cement unit 326operates in the first mode), however, control of the operation of thecement unit 326 may be switched to the first panel, e.g., to theexclusion of the second panel at the central package 302. This may donebecause the central package 302 may be moved away from the wellhead (toanother wellhead) during cementing operations, and thus control of thecementing process therefrom may be inconvenient.

FIG. 5 illustrates a simplified, conceptual view of the system 300,according to an embodiment. As shown, the generators 330 are coupled toat least some of the various subsystems (e.g., the central package 302,the mud pumps 324, and the cement unit 326, the tanks 320, and thecombined skid 314) via electrical lines. Any of the system 300components discussed above may be similarly coupled with the generator330, with those illustrated merely being one example among manycontemplated. Between the generators 330 and the subsystems areelectrical circuit breakers 500, which may be located physicallyproximal to the individual subsystems. By employing such local breakers500, the number of lines to the central package 302 and/or the combinedskid 314 may be reduced, as the breakers 500 may allow for powerreceived by the subsystems to be routed to the appropriate locations. Itwill be appreciated that additional components may be interposed betweenany of the subsystems and the generators 330, including withoutlimitation one or more VFDs, batteries, etc.

Further, each of the subsystems may include an individual programmablelogic controller (PLC) 502, while the system 300 may be controlled by acentral controller 503, which may be generally similar to, combinedwith, or provided by the rig control system discussed above. The PLCs502 provided for each of the subsystems may allow the individualsubsystems to be quasi-autonomous, e.g., able to perform certainoperations without command from the central controller 503. Further, thePLCs 502 may be in communication with individual human-machineinterfaces. This autonomy may facilitate adding and/or removingsubsystems, as the removal or addition of one may not affect the controlof the other subsystems. Further, the PLCs 502 may be able to receiveand implement relatively simple (e.g., deterministic orquasi-deterministic) commands from the central controller 503.

In some embodiments, one or some of the subsystems may include multiplesensors or other controllable elements or elements that providefeedback. Each of these may include a power line, signal line, or both.By providing a breaker 500 and a PLC 502 for each subsystem, the numberof connections running between a centralized control system (and/orbetween the movable central package 302 and one or more stationaryelements) may be reduced, as the breakers 500 and the PLCs 502 may eachbe configured to couple with multiple of these lines and reduce thelines extending from an individual one of the subsystems to one each forpower and signals. That is, the PLC 502 for one of the subsystems maycouple with multiple (e.g., dozens or more) sensors, and multiplex orotherwise package the signal data and send the data via a single (or, insome cases, multiple) line, such as an Ethernet line, to one or moreother PLCs 502 and/or to the centralized controller. Similarly, thebreaker 500 may receive a single power line and transmit power tomultiple components of the subsystem. Thus, the number of connections,wires, etc., that may be disconnected, moved, present safety risks, orotherwise be affected by the relative movement of the central package302 may be minimized.

In some embodiments, the methods of the present disclosure may beexecuted by a computing system. FIG. 6 illustrates an example of such acomputing system 600, in accordance with some embodiments. The computingsystem 600 may include a computer or computer system 601A, which may bean individual computer system 601A or an arrangement of distributedcomputer systems. The computer system 601A includes one or more analysismodules 602 that are configured to perform various tasks according tosome embodiments, such as one or more methods disclosed herein. Toperform these various tasks, the analysis module 602 executesindependently, or in coordination with, one or more processors 604,which is (or are) connected to one or more storage media 606. Theprocessor(s) 604 is (or are) also connected to a network interface 607to allow the computer system 601A to communicate over a data network 609with one or more additional computer systems and/or computing systems,such as 601B, 601C, and/or 601D (note that computer systems 601B, 601Cand/or 601D may or may not share the same architecture as computersystem 601A, and may be located in different physical locations, e.g.,computer systems 601A and 601B may be located in a processing facility,while in communication with one or more computer systems such as 601Cand/or 601D that are located in one or more data centers, and/or locatedin varying countries on different continents).

A processor may include a microprocessor, microcontroller, processormodule or subsystem, programmable integrated circuit, programmable gatearray, or another control or computing device.

The storage media 606 may be implemented as one or morecomputer-readable or machine-readable storage media. Note that while inthe example embodiment of FIG. 6 storage media 606 is depicted as withincomputer system 601A, in some embodiments, storage media 606 may bedistributed within and/or across multiple internal and/or externalenclosures of computing system 601A and/or additional computing systems.Storage media 606 may include one or more different forms of memoryincluding semiconductor memory devices such as dynamic or static randomaccess memories (DRAMs or SRAMs), erasable and programmable read-onlymemories (EPROMs), electrically erasable and programmable read-onlymemories (EEPROMs) and flash memories, magnetic disks such as fixed,floppy and removable disks, other magnetic media including tape, opticalmedia such as compact disks (CDs) or digital video disks (DVDs), BLURRY®disks, or other types of optical storage, or other types of storagedevices. Note that the instructions discussed above may be provided onone computer-readable or machine-readable storage medium, oralternatively, may be provided on multiple computer-readable ormachine-readable storage media distributed in a large system havingpossibly plural nodes. Such computer-readable or machine-readablestorage medium or media is (are) considered to be part of an article (orarticle of manufacture). An article or article of manufacture may referto any manufactured single component or multiple components. The storagemedium or media may be located either in the machine running themachine-readable instructions, or located at a remote site from whichmachine-readable instructions may be downloaded over a network forexecution.

In some embodiments, the computing system 600 contains one or more rigcontrol module(s) 608. In the example of computing system 600, computersystem 601A includes the rig control module 608. In some embodiments, asingle rig control module may be used to perform some or all aspects ofone or more embodiments of the methods disclosed herein. In alternateembodiments, a plurality of rig control modules may be used to performsome or all aspects of methods herein.

It should be appreciated that computing system 600 is only one exampleof a computing system, and that computing system 600 may have more orfewer components than shown, may combine additional components notdepicted in the example embodiment of FIG. 6, and/or computing system600 may have a different configuration or arrangement of the componentsdepicted in FIG. 6. The various components shown in FIG. 6 may beimplemented in hardware, software, or a combination of both hardware andsoftware, including one or more signal processing and/or applicationspecific integrated circuits.

Further, the steps in the processing methods described herein may beimplemented by running one or more functional modules in informationprocessing apparatus such as general purpose processors or applicationspecific chips, such as ASICs, FPGAs, PLDs, or other appropriatedevices. These modules, combinations of these modules, and/or theircombination with general hardware are all included within the scope ofprotection of the invention.

The foregoing description, for purpose of explanation, has beendescribed with reference to specific embodiments. However, theillustrative discussions above are not intended to be exhaustive or tolimit the disclosure to the precise forms disclosed. Many modificationsand variations are possible in view of the above teachings. Moreover,the order in which the elements of the methods described herein areillustrate and described may be re-arranged, and/or two or more elementsmay occur simultaneously. The embodiments were chosen and described inorder to explain at least some of the principals of the disclosure andtheir practical applications, to thereby enable others skilled in theart to utilize the disclosed methods and systems and various embodimentswith various modifications as are suited to the particular usecontemplated.

What is claimed is:
 1. A rig system, comprising: a movable central package comprising one or more devices to drill a well using a drill pipe; a mud pump coupled with the movable central package and configured to pump mud thereto; and a cement pump coupled with the movable central package, wherein the cement pump is operable in a first mode in which the cement pump pumps cement to the well, and a second mode in which the cement pump pumps mud to the well.
 2. The rig system of claim 1, wherein the movable central package is movable relative to the mud pump and the cement pump, and wherein the movable central package is configured for batch drilling.
 3. The rig system of claim 1, wherein the mud pump is configured to pump the mud in a first mode, and wherein the mud pump is configured to pump cement to the central package in a second mode.
 4. The rig system of claim 1, further comprising a combined skid that is movable along with the movable central package, wherein the combined skid comprises a managed pressure drilling system and a shaker assembly.
 5. The rig system of claim 4, wherein the combined skid comprises a shale shaker configured to separate solids from liquid in drilling mud received from the well, and wherein the rig system further comprises a fluid-residue skid configured to receive a solids residue form the drilling mud.
 6. The rig system of claim 1, wherein the central package, the mud pump, and the cement pump each include a programmable logic controller configured to execute one or more commands independent of a centralized control system, and wherein the programmable logic controller of each of the central package, the mud pump, and the cement pump is configured to implement one or more commands from the centralized control system.
 7. The rig system of claim 1, further comprising a mud tank having a programmable logic controller coupled therewith, wherein the programmable logic controller of the mud tank is quasi-autonomous.
 8. The rig system of claim 1, wherein the central package, the mud pump, and the cement pump are coupled to separate variable frequency drives (VFD) and separate electric circuit breakers.
 9. The rig system of claim 8, wherein each of the VFDs is coupled to the respective electric circuit breaker of the respective one of the central package, the mud pump, and the cement pump.
 10. The rig system of claim 1, further comprising a trunk line coupled on one end to the mud pump and the cement pump, and on an opposite end to the central package, the trunk line comprising a high-pressure mud line, a high-pressure cement line, a mud return line, a cement return line, and at least one high-power electrical line.
 11. The rig system of claim 1, wherein the central package comprises a first panel, the rig system further comprising a second panel located proximal to the cement pump, the first panel being configured to control the cement pump when the cement pump is in the second mode, and the second panel being configured to control the cement pump at least when the cement pump is in the first mode.
 12. The rig system of claim 11, wherein the first and second panels are configured to communicate with a variable frequency drive of the cement pump to adjust a speed thereof, and wherein the first and second panels are configured to avoid sending inconsistent commands to the variable frequency drive.
 13. The rig system of claim 1, further comprising a cement tank coupled with the cement pump, wherein the cement tank comprises a first premixed cement for use in a first cementing operation, and a second premixed cement for use in a second cementing operation, wherein the first and second premixed cements have different compositions.
 14. A method for drilling a well using a movable rig, comprising: pumping a mud into a wellbore using at least one mud pump while drilling the wellbore; pumping the mud into the wellbore using at least one cement pump in a first mode, while drilling the wellbore and while pumping mud into the wellbore using the at least one mud pump; and pumping cement into the wellbore using the at least one cement pump in a second mode.
 15. The method of claim 14, further comprising controlling the at least one cement pump in the first mode using a first panel positioned on a central package, the central package comprising a movable drilling rig.
 16. The method of claim 15, further comprising controlling the at least one cement pump in the second mode using a second panel positioned proximal to the at least one cement pump, wherein the movable drilling rig is movable with respect to the second panel.
 17. The method of claim 14, further comprising connecting a central package to the at least one mud pump and to the at least one cement pump using a trunk line, wherein the central package is movable with respect to the at least one mud pump and the at least one cement pump.
 18. The method of claim 17, further comprising: independently controlling an operation of the central package using a first controller and a first variable frequency drive, the first controller and the first variable frequency drive being coupled to the central package. independently controlling an operation of the at least one cement pump using a second controller and a second variable frequency drive, the second controller and the second variable frequency drive being coupled to the at least one cement pump. independently controlling an operation of the at least one mud pump using a third controller and a third variable frequency drive, the third controller and the third variable frequency drive being coupled to the at least one mud pump.
 19. A rig system, comprising: a movable central package comprising one or more devices to drill a well using a drill pipe; a mud pump coupled with the movable central package and configured to pump mud thereto, wherein the mud pump is configured to pump the mud in a first mode, and wherein the mud pump is configured to pump cement to the central package in a second mode; a cement pump coupled with the movable central package, wherein the cement pump is operable in a first mode in which the cement pump pumps cement to the well, and a second mode in which the cement pump pumps mud to the well; a combined skid that is movable along with the movable central package, wherein the combined skid comprises a managed pressure drilling system and a shaker assembly; a plurality of variable frequency drives (VFDs), wherein individual VFDs are separately coupled to the central package, the mud pump, and the cement pump; and a plurality of controllers, wherein individual controllers of the plurality of controllers are separately coupled to the central package, the mud pump, and the cement pump, to provide quasi-independent control thereof, wherein the movable central package is movable relative to the mud pump and the cement pump, and wherein the movable central package is configured for batch drilling.
 20. The rig system of claim 19, further comprising: a first panel coupled to the central package and being movable therewith, the first panel being configured to control the cement pump in the first mode; and a second panel, wherein the central package is movable with respect to the second panel, the second panel being configured to control the cement pump in the second mode. 